TORONTO, March 18, 2016 /CNW/ - Pacific Exploration & Production Corp. (TSX: PRE) (BVC: PREC) announced today the release of its audited consolidated financial statements for the year and quarter ended December 31, 2015, together with its management discussion and analysis ("MD&A"), Annual Information Form ("AIF") and Form 51-101 F1 - Statement of Reserves Data and Other Oil and Gas Information for the Company (the "F1 Report") in respect of the year ended December 31, 2015. These documents will be posted on the Company's website at www.pacific.energy, SEDAR at www.sedar.com, and the SIMEV website at www.superfinanciera.gov.co/web_valores/Simev. All values in this news release and the Company's financial disclosures are in U.S.$, unless otherwise stated.

Ronald Pantin, Chief Executive Officer of the Company, commented:

"The oil and gas industry has been profoundly altered as we are firmly entrenched in the second year of low international oil prices. The current pricing environment continues to threaten the economic health of the industry and many countries, with many E&P companies going into survival mode. Our immediate reaction in early 2015 to the lower oil price environment has allowed Pacific Exploration & Production Corp. to continue to deliver competitive operating results.

"We were well positioned through 2015 with an active hedging program to protect cash flow and that is borne out in our operating results. We continue to focus on maintaining and gaining operational efficiencies and have again been able to drive cash operating costs to record lows. The Company has maintained its drive to reduce cash operating costs to record levels and continues to control G&A spending.

"Our production increased slightly in 2015, where we achieved production from Colombia and Peru of 154,472 boe/d, including a marginal contribution from our recent addition of Block 192 in Peru. The Company has achieved its production guidance of 150 to 156 Mboe/d for 2015, representing modest growth over 2014.

"We continue to focus our production on light and medium oil assets. Exploration discoveries that were made in 2014 and further delineated in 2015 in the Colombian foothills provided near-term production stability. The modest exploration activity in 2015 also identified a number of other light oil prospects similar to the discoveries already made with a potential inventory of development and delineation drilling locations.

"In 2015, we earned revenues of $2,825 million and generated $1,031 million in Adjusted EBITDA1 and $579 million in funds flow from operations1. Despite the drop in oil prices, our operating netback for the year ended was $25.55/boe, benefitting from reduction of total costs complemented with a strong hedging position which generated superior realized prices.

"We continued to streamline our operations, generating further cost reductions during the fourth quarter of 2015 and record low cash operating costs. The Company achieved underlying operating costs of $18.64/boe and total operating costs (including overlift and other costs) of $22.52/boe, compared with $26.44/boe and $27.28/boe, respectively, for the fourth quarter of 2014. G&A expenses decreased to $221 million in 2015 from $361 million in 2014 as the Company continues to maintain its drive to control spending. Further cost savings and G&A reductions are still possible through 2016, due to additional restructuring of work processes.

"The Company developed and implemented a very workable strategy in late 2014 to address the collapse in oil prices – cash operating costs and G&A were cut, and capital expenditures were limited to only priority projects that allowed us to maintain production and protect the value of the asset base. However, the further collapse of oil prices early in the year has caused us to engage in a process to restructure the balance sheet.

"As we announced in January 2016, we invoked a 30-day grace period for making interest payments on two series of our outstanding bonds, to allow us to engage advisors and assess strategic alternatives to make the Company's capital structure more suitable to current market conditions. Subsequent to that announcement, we have entered into forbearance agreements with certain noteholders and banks until March 31, 2016, to allow the Company time to work with the Independent Committee of the Board of Directors, the Company's advisors, the banks and noteholders to come to a consensual and comprehensive restructuring of the Company's balance sheet.

"In summary, we believe strongly in the Company's assets and we are working diligently to ensure that the value of these assets are preserved for enhancement in the future. These are exceptionally difficult times for the oil industry, but we believe that the Company can weather the storm and continue to move forward with judicious use of our resources and efficient use of our technical and operational expertise. We are prepared for the long-term as well as for the opportunities before us and any challenges that may emerge."

Full Year and Fourth Quarter 2015 Results

Operational Highlights:

Net production after royalties for the full year totaled 154,472 boe/d, a 5% increase compared with 147,423 boe/d for 2014 and within the Company's guidance for the year of 150,000-156,000 boe/d. In the fourth quarter of 2015, average daily net production after royalties increased to 159,831 boe/d, higher by 9% as compared to the same period of 2014.

In 2015, the Company was able to maintain stable production levels in the Rubiales Field despite expected declines due to depletion. The Company continued to optimize wells and facilities to maximize production while minimizing capital expenditures and only drilling a minimum number of wells. Rubiales Field production comprised 35% of the net production for the year ended December 31, 2015.

The Company achieved a record underlying combined operating cost of $20.73/boe and a total combined operating cost (including overlift and other costs) of $22.96/boe, compared with $30.23/boe and $30.51/boe, respectively, in 2014. In the fourth quarter of 2015, total combined operating cost was $22.52/boe compared with $27.28/boe for the same period in 2014.

Financial Highlights:

Revenue decreased to $2,825 million compared to $4,950 million in 2014, reflecting the nearly 45% year-on-year decline in realized crude oil prices. Revenue for the fourth quarter of 2015 decreased to $652 million compared with $992 million for the same period in 2014, also due to the lower realized prices but partially offset by higher volumes sold in the period.

In 2015, revenue included $290 million in realized gains from oil hedging contracts entered into in 2014 and early 2015, helping to support the Company's realized prices above market rates during the year.

Average oil and gas sales (including trading) for the year were 159,113 boe/d, 1% higher than 158,026 boe/d in 2014. In February 2016, the Company terminated its outstanding hedging positions early for a total realized gain of $116 million, taking advantage of the recent positive mark-to-market movement to improve liquidity.

Combined operating netbacks on oil and gas for the year was $25.55/boe, 53% lower than the $54.84/boe in 2014. The decrease was mainly attributable to the decline in market prices for crude oil, partially offset by the reduction in combined operating costs achieved during the year.

The Company's average sales price per barrel of crude oil and natural gas was $48.51/boe for the year and $41.22/boe for the fourth quarter of 2015, down from $85.35/boe and $65.64/boe, respectively a year ago.

G&A expenses decreased to $221 million in 2015 from $361 million in 2014 as the Company continues to maintain its drive to control G&A and all non-essential spending and activities in light of the precipitous decrease in oil prices.

Adjusted EBITDA1 for the year was $1,031 million and Funds Flow1 was $579 million. Adjusted EBITDA and Funds Flow were 58% and 71% lower, respectively, compared with the year 2014.

Net loss for the year was $5,462 million, largely due to the $4,907 million non-cash impairment charge taken mainly on oil and gas assets and exploration expenses, reflecting the significant decline in crude oil prices. It is important to highlight that this impairment is required by International Financial Reporting Standards ("IFRS") accounting rules and can be reversed in whole or in part once market conditions improves with a better oil price trend.

Cash flow from operations in 2015 was $220 million, compared with $2,104 million in 2014.

Total capital expenditures decreased to $726 million in 2015 compared with $2,382 million in 2014. Capital expenditures will continue to approximately match cash flow, with spending mainly focused on high-impact and low-risk development work.

Additional Highlights:

Total 2P certified net reserves after royalties were 290.8 MMboe as at December 31, 2015, 43% lower compared with 510.9 MMboe as at December 31, 2014. Proved reserves (1P) were 197.8 MMboe as at December 31, 2015 compared with 315.0 MMboe as at December 31, 2014. The decrease in 2P reserves was primarily attributable to economic factors and technical revisions.

Fifteen exploration wells (including 11 appraisal wells) were drilled resulting in three discoveries and the confirmation of ten other previous discoveries for a total of 13 discoveries or a 87% success rate. Exploration activity during the year was primarily focused on the Central and Deep Llanos in Colombia that added an average of 14,591 bbl/d of light oil production in 2015.

On December 28, 2015, the Company obtained waivers of the debt leverage and net equity covenants under its $1 billion Revolving Credit Facility and the Bank of America, HSBC, and Bladex credit facilities (the "Credit Facilities").

On January 14, 2016, the Company announced it had elected to utilize the 30-day grace period under the applicable note indentures and not make interest payments of $66.2 million in the aggregate on its senior notes maturing in 2019 ("2019 Senior Notes") and those maturing in 2025 ("2025 Senior Notes", and together with the 2019 Senior Notes, the "Notes"). On February 18, 2016, the Company entered into an extension agreement (the "Noteholder Extension Agreement") with certain holders of the 2019 Senior Notes and 2025 Senior Notes. Under the terms of the Noteholder Extension Agreement, holders of approximately 34% of the aggregate principal amount of outstanding 2019 Senior Notes and 42% of the aggregate principal amount of outstanding 2025 Senior Notes have agreed, subject to certain terms and conditions, to forbear from declaring the principal amounts of the Notes (and certain additional amounts) due and payable as a result of certain specified defaults until March 31, 2016.

On February 19, 2016, the Company entered into separate forbearance agreements (the "Lender Forbearance Agreements") in respect of the Credit Facilities. Under the terms of the Lender Forbearance Agreements, the requisite lenders have also agreed, subject to certain terms and conditions, to forbear from declaring the principal amounts of such credit agreements due and payable as a result of certain specified defaults until March 31, 2016.

The Company has also breached several minimum credit rating covenants in certain operational agreements it has entered into as a result of downgrades of the Company's credit ratings during 2015, although waivers relating to these covenants have been granted for various limited periods.

The Company continues to work with its debtholders to formulate a comprehensive plan to address the current oil price environment and ensure the long-term viability of its business. The Company remains, and intends to remain, current with its suppliers, trade partners and contractors. Normal operations continue in Colombia and the other jurisdictions within which the Company operates. As noted in the notes to the Company's audited consolidated financial statements for the year and quarter ended December 31, 2015, there can be no certainty as to the ability of the Company to successfully restructure its long-term debts, amend operating agreements to the extent necessary to eliminate credit rating covenants, and obtain new financing should the low crude prices persist, and accordingly, there is a material uncertainty that may cast doubt on the ability of the Company to continue as a going concern.

Financial Results

Financial Summary

Year Ended December

Three Months Ended December

2015

2014

2015

2014

Oil & Gas Sales Revenues ($ millions)

2,824.5

4,950.0

652.0

991.5

Adjusted EBITDA ($ millions)1, 4

1,031.3

2,484.1

182.9

419.3

Adjusted EBITDA Margin (Adjusted EBITDA/Revenues)

37%

50%

28%

42%

Adjusted EBITDA per share1, 4

3.29

7.87

0.58

1.33

Cash Flow (Funds Flow from Operations) ($ millions)1

578.5

2,021.2

42.3

409.8

Cash Flow (Funds Flow from Operations) per share1

1.85

6.41

0.13

1.30

Net (Loss) earnings from operations before impairment

(503.8)

832.3

(198.8)

(36.6)

Net (Loss) Earnings ($ millions) 2

(5,461.9)

(1,309.6)

(3,895.9)

(1,660.9)

Net (Loss) Earnings per share

(17.44)

(4.15)

(12.44)

(5.26)

Net Production (boe/d)

154,472

147,423

159,831

147,075

Sales Volumes (boe/d)

159,113

158,026

171,928

161,445

(COP$ / US$) Exchange Rate3

3,149.47

2,392.46

3,149.47

2,392.46

Average Shares Outstanding – basic (millions)

313.3

315.5

313.3

315.9

1The terms Adjusted EBITDA and cash flow (Funds Flow from Operations) are non-IFRS measures. These non-IRFS measures do not have any standardized meanings and therefore are unlikely to be comparable to similar measures presented by other companies. These non-IFRS measures are included because Management uses this information to analyze operating performance, leverage and liquidity. Therefore, these measures should not be considered in isolation or as a substitute for measures of performance prepared in accordance with IFRS. Please see "Additional Financial Measures" in the MD&A.

2Net earnings attributable to equity holders of the parent.

3COP/USD exchange rate fluctuations can have a significant impact on the Company's accounting net earnings, in the form of unrealized foreign currency translation on the Company's financial assets and liabilities and deferred tax balances that are denominated in COP.

4The Company uses the non-IFRS measure Adjusted EBITDA, whereas in the past the term EBITDA was used. Our calculation of this measure has not changed from previous quarters, but the terminology has changed, further to guidance provided by the Ontario Securities Commission.

Production

Net Production Summary

Year EndedDecember

Three Months EndedDecember

2015

2014

2015

2014

Oil and Liquids (bbl/d)

Colombia

139,659

134,435

138,906

133,731

Peru

5,586

2,641

10,462

3,288

Total Oil and Liquids (bbl/d)

145,245

137,076

149,368

137,019

Natural Gas (boe/d)1

Colombia

9,227

10,347

10,463

10,056

Total Natural Gas (boe/d)

9,227

10,347

10,463

10,056

Total Equivalent Production (boe/d)

154,472

147,423

159,831

147,075

1Colombian standard natural gas conversion ratio of 5.7 Mcf/bbl.

Additional production details are available in the MD&A.

During 2015, net production after royalties totaled 154,472 boe/d, a 5% increase compared with 147,423 boe/d for 2014, within the Company's guidance for the year (150,000-156,000 boe/d). In the fourth quarter of 2015, average daily net production after royalties increased to 159,831 boe/d, higher by 9% as compared to the same period of 2014. The Company was able to maintain stable production levels in the Rubiales Field despite the declines as previously expected. The Company continued to optimize wells and facilities to maximize production while minimizing capital expenditures. Light and medium net oil production for the full year totaled 57,022 bbl/d, an increase of 16% compared to 2014. Part of the increase corresponds to production from Block 192 in Peru, where the Company became the operator on August 30, 2015. Heavy oil production from Quifa and other fields also increased by 9% during 2015 compared with 2014. Light and medium oil and heavy crude oil production (excluding the Rubiales Field) production now represents 37% and 35%, respectively, of total net oil and gas production, while production from the Rubiales Field represented 35% of the total net production, down from 41% in 2014.

Production and Sales Volumes

Production to Total Sales Reconciliation

Year EndedDecember

Three Months EndedDecember

2015

2014

2015

2014

Net Production

Colombian oil (bbl/d)

139,659

134,435

138,906

133,731

Colombian gas (boe/d)

9,227

10,347

10,463

10,056

Peruvian oil (bbl/d)

5,586

2,641

10,462

3,288

Total Net Production (boe/d)

154,472

147,423

159,831

147,075

Sales Volumes (boe/d)

Production Volumes (boe/d)

154,472

147,423

159,831

147,075

Diluent Volumes (bbl/d)

323

2,405

316

1,795

Oil for Trading Volumes (bbl/d)

7,307

12,085

889

14,237

Overlift/Underlift (bbl/d)

3,685

0

14,082

(43)

Inventory Movement and Other (bbl/d)

(6,674)

(2,655)

(3,190)

(1,619)

Total Volumes Sold (boe/d)

159,113

158,026

171,928

161,445

Additional production and sales volume details are available in the MD&A.

The Company produces and sells crude oil and natural gas. It also purchases liquids and crude oil from third parties for trading purposes and distillate for diluent mixing with heavy oil production, which are included in the reported "volumes sold". Sales volumes are also impacted by the relative movement in inventories during a reporting period. Both revenues and costs are recognized on the respective volumes sold during the period.

Diluent volumes for the year decreased to 323 bbl/d from 2,405 bbl/d in 2014. Diluent volumes have decreased by 94% since the year ended 2013 as the Company successfully utilizes the production of light and medium oil from prior acquisitions and new discoveries, plus accessing new lower cost diluent service arrangements.

Oil for trading volumes in 2015 decreased to 7,307 bbl/d from 12,085 bbl/d in 2014. The drop in the volumes sold in 2015 was mainly attributable to the reduction in the oil production in Colombia, which increased the available capacity in the pipelines for other traders to compete with better conditions. The inventory build and other use was 6,647 bbl/d in 2015 compared to 2,655 bbl/d in 2014.

Total volumes sold, composed of production volumes available for sale, purchased diluent volumes, oil for trading volumes, and inventory balance changes, increased to 159,113 boe/d in 2015 from 158,026 boe/d in 2014.

Operating Netbacks and Sales Volumes

Oil and Gas Production Volumes and Netbacks

Year EndedDecember 2015

Year EndedDecember 2014

Three Months Ended December 2015

Three Months EndedDecember 2014

Oil

Gas

Combined

Oil

Gas

Combined

Oil

Gas

Combined

Oil

Gas

Combined

Production VolumesSold (boe/d)1

142,595

9,211

151,806

135,622

10,319

145,941

160,498

10,541

171,039

137,083

10,125

147,208

Crude Oil and NaturalGas Sales Price ($/boe)

49.56

32.28

48.51

89.46

31.27

85.35

41.86

31.43

41.22

68.27

29.97

65.64

Production Costs ($/boe)

8.19

2.54

7.85

15.98

3.86

15.12

8.12

2.74

7.79

14.40

4.42

13.71

Transportation Costs ($/boe)

11.51

0.42

10.84

13.93

0.07

12.95

9.30

-

8.73

11.70

0.33

10.92

Diluent Costs ($/boe)

2.17

-

2.04

2.33

-

2.16

2.26

-

2.12

1.95

-

1.81

Sub-Total Costs ($/boe)

21.87

2.96

20.73

32.24

3.93

30.23

19.68

2.74

18.64

28.05

4.75

26.44

Other Costs ($/boe)2

1.56

2.02

1.59

1.42

2.04

1.46

1.60

2.35

1.64

0.80

1.75

0.87

Overlift/Underlift Costs ($/boe)

0.68

0.07

0.64

(1.26)

(0.03)

(1.18)

2.37

0.33

2.24

(0.03)

0.04

(0.03)

Total Costs ($/boe)

24.11

5.05

22.96

32.40

5.94

30.51

23.65

5.42

22.52

28.82

6.54

27.28

Operating Netback ($/boe)

25.45

27.23

25.55

57.06

25.33

54.84

18.21

26.01

18.70

39.45

23.43

38.36

1Production volumes sold excludes oil for trading volumes and includes diluent volumes sold.

2Includes royalties paid in cash.

Additional cost and netback details are available in the MD&A.

Throughout 2015 the Company continued to streamline its operations to generate further cost reductions. The Company achieved a record underlying combined operating cost of $20.73/boe and a total combined operating cost (including overlift and other costs) of $22.96/boe, compared with $30.23/boe and $30.51/boe, respectively, in 2014. The decreased unit cost is mainly a result of operating cost optimization and a 32% depreciation of the Colombian peso against the U.S. dollar. During the year, there was a disruption of the Bicentenario Pipeline of 204.5 days. However, the Company was able to source available operational capacity in the OCENSA pipeline at comparable per unit costs.

The Company traded an average of 7,307 bbl/d in 2015 as compared with 12,085 bbl/d in 2014. However, the average netback for volumes traded in 2015 was $2.81/bbl, a gross margin of $7.5 million; versus the netback captured in 2014 of $0.67/bbl, a gross margin of $2.9 million. Similar trend of improved netbacks was observed during the fourth quarter of 2015. Trading volumes vary with opportunities in the market place and any one quarter is not a good indicator of future trading potential. Additional oil for trading details are available in the MD&A.

These reserves reports were prepared in accordance with the definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and the National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI 51-101") and included in the F1 Report filed on SEDAR. Additional reserves information as required under NI 51-101 are included in the Company's AIF dated March 18, 2016.

All reserves presented are based on forecast pricing and estimated costs effective December 31, 2015 as determined by the Company's independent reserves evaluators. The Company's net reserves after royalties incorporate all applicable royalties under Colombia and Peru fiscal legislation based on forecast pricing and production rates, including any additional participation interest ("PAP") related to the price of oil applicable to certain Colombian blocks, as at year-end 2015.

2015 2P Reserves Reconciliation

Oil Equivalent Gross2P Reserves(MMboe)2

Oil Equivalent Net2P Reserves(MMboe)2

December 31, 20141

560.6

510.9

Net Additions and Technical Revisions

(63.1)

(50.4)

Economic Revisions

(115.3)

(113.7)

Production3

(64.4)

(56.0)

December 31, 2015

317.8

290.8

Notes:

1Statement of Reserves Data and Other Oil and Gas Information as of December 31, 2015, filed on SEDAR in Form 51-101 F1, on March 18, 2016.

2Boe is expressed herein using the conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy for Colombian natural gas and 5.6 Mcf: 1 bbl required by the Peru Oil Ministry for Peruvian natural gas. A reconciliation to NI 51-101 conversion standard of 6 Mcf: 1 bbl is provided in the "Advisories" section of this news release.

3Production represents the production for the twelve month period ended December 31, 2015.

Note: Numbers in the table may not add due to rounding differences.

In 2015, the Company's reserves were impacted by significantly lower oil price forecasts resulting in economic revisions plus the impact of normal course technical revisions as assessed by the Company's independent reserves evaluators. The decrease in 2P reserves was primarily attributable to economic factors and technical revisions. Economic revisions as a result of lower oil prices can usually be reversed with higher oil prices, which could result in positive economic revisions in the future.

Reserves at December 31, 2015 (MMboe1)

Country

Field

Total Proved (P1)

Probable (P2)

Proved Plus Probable (2P)

Hydrocarbon Type

Gross

Net

Gross

Net

Gross

Net

Colombia

Rubiales

11.5

9.2

-

-

11.5

9.2

Heavy Oil

Quifa SW

54.2

48.0

4.0

3.5

58.3

51.4

Heavy Oil

Other Heavy Oil Blocks2

46.8

40.8

36.2

31.0

83.0

71.8

Heavy Oil

Light/Medium Oil Blocks

53.3

49.0

29.8

27.4

83.1

76.4

Light & Medium Oil &Associated Natural Gas

Natural Gas Blocks3

40.4

40.3

13.7

13.7

54.1

54.1

Natural Gas

Sub-total

206.2

187.4

83.8

75.6

290.0

263.0

Oil & Natural Gas

Peru

Light/Medium Oil & Natural Gas4

10.4

10.4

17.4

17.4

27.8

27.8

Oil & Natural Gas

Total at Dec. 31, 2015

216.6

197.8

101.2

93.0

317.8

290.8

Oil & Natural Gas

Total at Dec. 31, 2014

348.8

315.0

211.7

195.9

560.5

510.9

Difference

(132.2)

(117.2)

(110.5)

(102.9)

(242.7)

(220.1)

2015 Production

64.3

55.9

Total ReservesIncorporated

(178.4)

(164.2)

Notes:

1See 'Boe Conversion" section in the Advisories, at the end of this news release.

In the table above, Gross refers to WI before royalties, Net refers to WI after royalties; numbers in table may not add due to rounding differences.

Exploration Update

Exploration activity during the year was primarily focused on the Central and Deep Llanos in Colombia and added an average of 14,591 bbl/d of light oil production in 2015. In 2015, the Company drilled or was a partner in 15 exploration wells (including 11 appraisal wells) resulting in three discoveries and the confirmation of ten other previous discoveries for a total of 13 discoveries or a 87% success rate. During the fourth quarter of 2015 no drilling activity was performed.

About Pacific:

Pacific Exploration & Production Corp. is a Canadian public company and a leading explorer and producer of natural gas and crude oil, with operations focused in Latin America. The Company has a diversified portfolio of assets with interests in more than 70 exploration and production blocks in various countries including Colombia, Peru, Guatemala, Brazil, Guyana and Belize. The Company's strategy is focused on sustainable growth in production & reserves and cash generation. Pacific Exploration & Production is committed to conducting business safely, in a socially and environmentally responsible manner.

The Company's common shares trade on the Toronto Stock Exchange and La Bolsa de Valores de Colombia under the ticker symbols PRE, and PREC, respectively.

Advisories:

Cautionary Note Concerning Forward-Looking Statements

This news release contains forward-looking statements. All statements, other than statements of historical fact, that address activities, events or developments that the Company believes, expects or anticipates will or may occur in the future (including, without limitation, statements regarding estimates and/or assumptions in respect of production, revenue, cash flow and costs, reserve and resource estimates, potential resources and reserves and the Company's exploration and development plans and objectives and its strategy) are forward-looking statements. These forward-looking statements reflect the current expectations or beliefs of the Company based on information currently available to the Company. Forward-looking statements are subject to a number of risks and uncertainties that may cause the actual results of the Company to differ materially from those discussed in the forward-looking statements, and even if such actual results are realized or substantially realized, there can be no assurance that they will have the expected consequences to, or effects on, the Company. Factors that could cause actual results or events to differ materially from current expectations include, among other things: the Company's ability to continue as a going concern; volatility in market prices for oil and natural gas; a continued depressed oil price environment with a potential of further decline; default under the Credit Facilities and/or the Company's senior notes due to a breach of covenants therein; early termination of one or more of the Lender Forbearance Agreements and/or the Noteholder Extension Agreement; amounts becoming due and payable under the Credit Facilities and/or the Senior Notes, notwithstanding the entering into of the Lender Forbearance Agreements and the Noteholder Extension Agreement, whether through the actions of holders of the 2019 Senior Notes and 2025 Senior Notes or the trustee under each respective indenture or otherwise; the impact of events of defaults in respect of the Credit Facilities, 2019 Senior Notes and 2025 Senior Notes on other material contracts of the Company, including but not limited to, cross-defaults resulting in acceleration of amounts payable thereunder or the termination of such agreements; failure of the Company to reach an agreement with its creditors to restructure the Company's capital structure; failure to satisfy any terms or conditions of any agreement with the Company's creditors on a proposed restructuring; any negative impact on the Company's current operations as a result of any proposed restructuring or failure to reach an agreement with the creditors thereon; failure to satisfy the terms and conditions of any one of the Company's waiver agreements with applicable creditors or counterparties or any other waiver, failure to obtain further extensions of any such waivers, or failure to obtain waivers of other covenants, if and when required; the terms of any waivers, including the impact on the Company of any restrictions imposed upon it in connection with any waiver; failure to obtain additional financial resources to avoid the need to seek relief under the bankruptcy and insolvency laws in one or more of Canada, the United States, Colombia and/or other jurisdictions (or avoid an involuntary petition for bankruptcy relief or similar creditor action filed against the Company); investors' perceptions of the Company's prospects and the prospects of the oil and gas industry in Colombia and the other countries where the Company operates and/or has investments; expectations regarding the Company's ability to raise capital and to continually add to reserves through acquisitions and development; inability to continue meeting the listing requirements of the exchanges on which the Company's securities are listed; the value of the Company's equity securities being reduced to zero as a result of an insolvency filing and that such proceeding may ultimately result in the cancellation of the Company's equity securities; the effect of ratings downgrades on the Company's business and operations; political developments in Colombia, Guatemala, Peru, Brazil, Guyana and Mexico; liabilities inherent in oil and gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions and/or past integration problems; geological, technical, drilling and processing problems; fluctuations in foreign exchange or interest rates and stock market volatility; delays in obtaining required environmental and other licences; uncertainty of estimates of capital and operating costs, production estimates and estimated economic return; the possibility that actual circumstances will differ from estimates and assumptions; uncertainties relating to the availability and costs of financing needed in the future; changes in income tax laws or changes in tax laws, accounting principles and incentive programs relating to the oil and gas industry; and the other factors discussed under the heading entitled "Risk Factors" and elsewhere in the Company's AIF dated March 18, 2016 filed on SEDAR at www.sedar.com. Information relating to "reserves" or "resources" is also deemed to be forward-looking information, as it involves an implied assessment based on certain estimates and assumptions about the profitable production of the resources and reserves described. Any forward-looking statement speaks only as of the date on which it is made and, except as may be required by applicable securities laws, the Company disclaims any intent or obligation to update any forward-looking statement, whether as a result of new information, future events or results or otherwise. Although the Company believes that the assumptions inherent in the forward-looking statements are reasonable, forward-looking statements are not guarantees of future performance and accordingly undue reliance should not be put on such statements due to the inherent uncertainty therein.

In addition, reported production levels may not be reflective of sustainable production rates and future production rates may differ materially from the production rates reflected in this press release due to, among other factors, difficulties or interruptions encountered during the production of hydrocarbons.

The recovery and reserves estimates of crude oil and natural gas reserves provided in this news release taken from the independent reserve reports are estimates only, and there is no guarantee that the estimated reserves will be recovered. Actual crude oil and natural gas reserves may eventually be greater than or less than the estimates provided.

The estimated values disclosed in this news release do not represent fair market value. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation.

Boe Conversion

The term "boe" is used in this news release. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 5.7 Mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

The Company's natural gas reserves are contained in the La Creciente, Guama and other bocks in Colombia as well as in the Piedra Redonda field in Block Z-1, Peru. For all natural gas reserves in Colombia, boe's have been expressed using the Colombian conversion standard of 5.7 Mcf: 1 bbl required by the Colombian Ministry of Mines and Energy, and for all natural gas reserves in Peru, boe's have been expressed using the Peruvian conversion standard of 5.626 Mcf: 1 bbl required by Perupetro S.A. If a conversion standard of 6.0 Mcf: 1 bbl was used for all of the Company's natural gas reserves, this would result in a reduction in the Company's net P1 and 2P reserves of approximately 4.9 and 6.9 MMboe, respectively.

Definitions

Bcf

Billion cubic feet.

Bcfe

Billion cubic feet of natural gas equivalent.

bbl

Barrel of oil.

bbl/d

Barrel of oil per day.

boe

Barrel of oil equivalent. Boe's may be misleading, particularly if used in isolation. The Colombian standard is a boe conversion ratio of 5.7 Mcf:1 bbl and is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

boe/d

Barrel of oil equivalent per day.

Mbbl

Thousand barrels.

Mboe

Thousand barrels of oil equivalent.

MMbbl

Million barrels.

MMboe

Million barrels of oil equivalent.

Mcf

Thousand cubic feet.

Million Tons LNG

One million tons of LNG (Liquefied Natural Gas) is equivalent to 48 Bcf or 1.36 billion m3 of natural gas.

Net Production

Company working interest production after deduction of royalties.

Total Field Production

100% of total field production before accounting for working interest and royalty deductions.

Gross Production

Company working interest production before deduction of royalties.

WTI

West Texas Intermediate Crude Oil.

Translation

This news release was prepared in the English language and subsequently translated into Spanish. In the case of any differences between the English version and its translated counterparts, the English document should be treated as the governing version.